U.S. patent application number 12/085210 was filed with the patent office on 2009-07-23 for profile control apparatus and method for production and injection wells.
Invention is credited to Franz D. Bunnell, Manh V. Phi.
Application Number | 20090183873 12/085210 |
Document ID | / |
Family ID | 36302204 |
Filed Date | 2009-07-23 |
United States Patent
Application |
20090183873 |
Kind Code |
A1 |
Bunnell; Franz D. ; et
al. |
July 23, 2009 |
Profile Control Apparatus and Method for Production and Injection
Wells
Abstract
Systems and associated methods for use in the production of
hydrocarbons are described. The systems include a first tubular
member and a second tubular member at least partially enclosing the
first tubular member. Each of the first and second tubular members
have a non-permeable longitudinal section and a permeable
longitudinal section. The non-permeable longitudinal section of the
second tubular member is disposed adjacent to the permeable
longitudinal section of the first tubular member. Similarly, the
permeable longitudinal section of the second tubular member is
disposed adjacent to the non-permeable longitudinal section of the
first tubular member. The permeable longitudinal section of the
second tubular member is separated from the permeable longitudinal
section of the first tubular member by a specific longitudinal
distance.
Inventors: |
Bunnell; Franz D.; (The
Woodlands, TX) ; Phi; Manh V.; (Houston, TX) |
Correspondence
Address: |
Exxon Mobil Upstream;Research Company
P.O. Box 2189, (CORP-URC-SW 359)
Houston
TX
77252-2189
US
|
Family ID: |
36302204 |
Appl. No.: |
12/085210 |
Filed: |
October 12, 2006 |
PCT Filed: |
October 12, 2006 |
PCT NO: |
PCT/US2006/039878 |
371 Date: |
May 19, 2008 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60751676 |
Dec 19, 2005 |
|
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|
Current U.S.
Class: |
166/278 ;
166/228 |
Current CPC
Class: |
E21B 43/12 20130101;
E21B 43/086 20130101 |
Class at
Publication: |
166/278 ;
166/228 |
International
Class: |
E21B 43/10 20060101
E21B043/10; E21B 43/08 20060101 E21B043/08; E21B 43/12 20060101
E21B043/12; E21B 43/02 20060101 E21B043/02 |
Claims
1. A system associated with the production of hydrocarbons
comprising: a first tubular member disposed within a wellbore
environment comprising: a non-permeable longitudinal section of the
first tubular member; and a permeable longitudinal section of the
first tubular member having a first plurality of openings between a
first central channel of the first tubular member and a region
external to the first tubular member; and a second tubular member
at least partially enclosing the first tubular member, the second
tubular member comprising: a non-permeable longitudinal section of
the second tubular member in substantial radial alignment with the
permeable longitudinal section of the first tubular member; and a
permeable longitudinal section of the second tubular member having
a second plurality of openings between an internal region of the
second tubular member and a region external to the second tubular
member that permits particles less than a particular size to pass,
wherein the permeable longitudinal section of the second tubular
member is in substantial radial alignment with the non-permeable
longitudinal section of the first tubular member and the permeable
longitudinal section of the second tubular member is separated from
the permeable longitudinal section of the first tubular member by a
specific longitudinal distance, wherein the specific longitudinal
distance is calculated based on properties associated with the
wellbore environment.
2. The system of claim 1 wherein the specific longitudinal distance
is adapted to form a sand bridge adjacent to the permeable
longitudinal section of the first tubular member.
3. The system of claim 1 wherein the specific longitudinal distance
is based on a calculated pressure drop for fluids flowing through
the permeable longitudinal section of the second tubular member to
the permeable longitudinal section of the first tubular member.
4. The system of claim 1 wherein the first tubular member comprises
a perforated base pipe and the first plurality of openings are
slots formed within the perforated base pipe that are configured to
prevent sand particles from entering the first central opening.
5. The system of claim 4 wherein the second tubular member is a
production casing string and the second plurality of openings is
perforations in the production casing string.
6. The system of claim 4 wherein the second tubular member
comprises a perforated outer jacket and the second plurality of
openings are formed within the perforated outer jacket and
configured to allow sand particles to enter a passage between the
perforated outer jacket and the perforated base pipe.
7. The system of claim 6 comprising a plurality of axial rods
disposed between the perforated outer jacket and the perforated
base pipe.
8. The system of claim 6 wherein the perforated outer jacket and
the perforated base pipe are coupled together as a wellbore
tool.
9. The system of claim 6 comprising end caps secured to the
perforated outer jacket and the perforated base pipe.
10. The system of claim 1 wherein the first tubular member is
configured to provide produced hydrocarbons.
11. The system of claim 1 wherein the specific longitudinal
distance is calculated to achieve a target pressure drop at a given
flow rate.
12. The system of claim 2 wherein the specific longitudinal
distance is calculated to form a sand bridge of sufficient size to
block the flow of water into the first tubular member.
13. The system of claim 1 wherein the properties of the wellbore
environment comprise geometry of the wellbore, fluid content within
the wellbore, and sand content of the wellbore.
14. A system associated with production of hydrocarbons comprising:
a wellbore utilized to produce hydrocarbons from a subsurface
reservoir; a production tubing string disposed within the wellbore;
a perforated base pipe coupled to the production tubing string and
disposed within the wellbore adjacent to subsurface reservoir, the
perforated base pipe comprising: a non-permeable longitudinal
section of the perforated base pipe; and a permeable longitudinal
section of the perforated base pipe having a plurality of slots
between a central channel of the perforated base pipe and a region
external to the perforated base pipe; and a tubular member at least
partially enclosing the perforated base pipe, the tubular member
comprising: a non-permeable longitudinal section of the tubular
member disposed adjacent to the permeable longitudinal section of
the perforated base pipe; and a permeable longitudinal section of
the tubular member having a plurality of openings between an
internal region of the tubular member and a region external to the
tubular member that allows particles less than a particular size to
pass, wherein the permeable longitudinal section of the tubular
member is disposed adjacent to the non-permeable longitudinal
section of the perforated base pipe and the permeable longitudinal
section of the tubular member is separated from the permeable
longitudinal section of the perforated base pipe by a specific
longitudinal distance, wherein the specific longitudinal distance
is calculated based on properties associated with the wellbore.
15. The system of claim 14 wherein the properties of the wellbore
comprise the geometry of the wellbore, fluid content within the
wellbore, and sand content of the wellbore.
16. The system of claim 14 wherein the specific longitudinal
distance is based on a calculated pressure drop for fluids flowing
through the permeable longitudinal section of the tubular member to
the permeable longitudinal section of the perforated base pipe.
17. The system of claim 14 wherein the plurality of slots are
configured to prevent sand particles from entering the central
opening of the perforated base pipe.
18. The system of claim 17 wherein the tubular member is a
production casing string disposed within the wellbore and enclosing
the perforated base pipe and the plurality of openings is
perforations in the production casing string.
19. The system of claim 17 wherein the tubular member comprises a
perforated outer jacket and the plurality of openings are formed
within the perforated outer jacket and configured to allow sand
particles to enter a passage between the perforated outer jacket
and the perforated base pipe.
20. The system of claim 19 comprising a plurality of axial rods
disposed between the perforated outer jacket and the perforated
base pipe.
21. The system of claim 19 wherein the perforated outer jacket and
the perforated base pipe are welded together as a wellbore
tool.
22. The system of claim 14 wherein the perforated base pipe is
configured to produce hydrocarbons through the production tubing
string.
23. The system of claim 14 wherein the specific longitudinal
distance promotes the formation of a sand bridge adjacent to the
permeable longitudinal section of the perforated base pipe.
24. The system of claim 14 wherein the specific longitudinal
distance is calculated to achieve a target pressure drop at a given
flow rate.
25. The system of claim 24 wherein the specific longitudinal
distance is calculated based on at least one of chamber flow area,
permeability of the plugging material and fluid properties.
26. The system of claim 16 wherein the specific longitudinal
distance is calculated to form a sand bridge of sufficient size to
block the flow of water into the first tubular member.
27. A method associated with production of hydrocarbons comprising:
calculating a specific longitudinal distance based on properties
associated with a wellbore environment; providing a first tubular
member, wherein the first tubular member comprises a non-permeable
longitudinal section of the first tubular member and a permeable
longitudinal section of the first tubular member that allows fluids
to flow between a first central channel and a region external to
the first tubular member; providing a second tubular member at
least partially enclosing the first tubular member, wherein the
second tubular member comprises a non-permeable longitudinal
section of the second tubular member disposed adjacent to the
permeable longitudinal section of the first tubular member and a
permeable longitudinal section of the second tubular member that
allows fluids and sand particles to flow between a second central
channel and a region external to the second tubular member, and the
permeable longitudinal section of the second tubular member; and
disposing the non-permeable longitudinal section of the first
tubular member adjacent to the permeable longitudinal section of
the second tubular member, wherein permeable longitudinal section
of the first tubular member permeable is separated from the
permeable longitudinal section of the second tubular member by the
specific longitudinal distance.
28. The method of claim 27 comprising disposing the first tubular
member and the second tubular member within a wellbore.
29. The method of claim 28 comprising producing hydrocarbons from a
subsurface formation via the first tubular member and the second
tubular member.
30. The method of claim 28 comprising injecting fluids into the
wellbore via the first tubular member and the second tubular
member.
31. The method of claim 27 comprising forming a sand bridge
adjacent to the permeable longitudinal section of the first tubular
member.
32. A method of producing hydrocarbons using the system of claim
1.
33. A method of producing hydrocarbons using the system of claim
14.
34. The method of claim 27, wherein the properties associated with
the wellbore environment comprise geometry of a wellbore, fluid
content within a wellbore, and sand content of the wellbore
environment.
35. A system associated with the production of hydrocarbons
comprising: a first tubular member comprising: a non-permeable
longitudinal section of the first tubular member; a permeable
longitudinal section of the first tubular member having a first
plurality of openings between a first central channel of the first
tubular member and a region external to the first tubular member;
and a second tubular member at least partially enclosing the first
tubular member, the second tubular member comprising: a
non-permeable longitudinal section of the second tubular member in
substantial radial alignment with the permeable longitudinal
section of the first tubular member; and a permeable longitudinal
section of the second tubular member having a second plurality of
openings between an internal region of the second tubular member
and a region external to the second tubular member that allows
particles less than a particular size to pass, wherein the
permeable longitudinal section of the second tubular member is in
substantial radial alignment with the non-permeable longitudinal
section of the first tubular member, and wherein a plurality of
axial partitions are disposed between the first and second tubular
members to form a plurality of axial chambers.
36. The system of claim 35 wherein the first tubular member
comprises a perforated base pipe and the first plurality of
openings are slots formed within the perforated base pipe that are
configured to prevent sand particles from entering the first
central channel.
37. The system of claim 36 wherein the second tubular member is a
production casing string and the second plurality of openings is
perforations in the production casing string.
38. The system of claim 36 wherein the second tubular member
comprises a perforated outer jacket and the second plurality of
openings are formed within the perforated outer jacket and
configured to allow sand particles to enter a passage between the
perforated outer jacket and the perforated base pipe.
39. The system of claim 38 wherein the perforated outer jacket and
the perforated base pipe are coupled together as a wellbore
tool.
40. The system of claim 38 comprising end caps secured to the
perforated outer jacket and the perforated base pipe.
41. The system of claim 35 wherein the first tubular member is
configured to provide a flow path for produced hydrocarbons.
42. The system of claim 35 wherein there are eight axial
chambers.
43. A method of producing hydrocarbons using the system of claim
35.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Application No. 60/751,676, filed 19 Dec. 2005.
FIELD OF THE INVENTION
[0002] This invention relates generally to an apparatus and method
for use in wellbores. More particularly, this invention relates to
a wellbore apparatus and method for producing hydrocarbons and
managing sand production.
BACKGROUND
[0003] This section is intended to introduce the reader to various
aspects of art, which may be associated with exemplary embodiments
of the present invention, which are described and/or claimed below.
This discussion is believed to be helpful in providing the reader
with information to facilitate a better understanding of particular
techniques of the present invention. Accordingly, it should be
understood that these statements are to be read in this light, and
not necessarily as admissions of prior art.
[0004] The production of hydrocarbons, such as oil and gas, has
been performed for numerous years. To produce these hydrocarbons, a
production system may utilize various devices, such as sand control
devices and other tools, for specific tasks within a well.
Typically, these devices are placed into a wellbore completed in
either cased-hole or open-hole completion. In cased-hole
completions, wellbore casing is placed in the wellbore and
perforations are made through the casing into subterranean
formations to provide a flow path for formation fluids, such as
hydrocarbons, into the wellbore. Alternatively, in open-hole
completions, a production string is positioned inside the wellbore
without wellbore casing. The formation fluids flow through the
annulus between the subsurface formation and the production string
to enter the production string.
[0005] When producing fluids from subterranean formations,
especially poorly consolidated formations or formations weakened by
increasing downhole stress due to wellbore excavation and fluids
withdrawal, it is possible to produce solid material (for example,
sand) along with the formation fluids. In some cases, formations
may produce hydrocarbons without sand until the onset of water
production from the formations. With the onset of water, these
formations collapse or fail due to increased drag forces (water
generally has higher viscosity than oil or gas) and/or dissolution
of material holding sand grains together.
[0006] The sand/solids and water production typically results in a
number of problems. These problems include productivity loss,
equipment damage, and/or increased treating, handling and disposal
costs. For example, the sand/solids production may plug or restrict
flow paths resulting in reduced productivity. The sand/solids
production may also cause severe erosion damaging equipment, which
may create well control problems. When produced to the surface, the
sand is removed from the flow stream and has to be disposed of
properly, which increases the operating costs of the well. Water
production also reduces productivity. For instance, because water
is heavier than hydrocarbon fluids, it takes more pressure to move
it up and out of the well. That is, the more water produced, the
less pressure available to move the hydrocarbons, such as oil. In
addition, water is corrosive and may cause severe equipment damage
if not properly treated. Similar to the sand, the water also has to
be removed from the flow stream and disposed of properly.
[0007] The sand/solids and water production may be further
compounded with wells that have a number of different completion
intervals and the formation strength may vary from interval to
interval. Because the evaluation of formation strength is
complicated, the ability to predict the timing of the onset of sand
and/or water is limited. In many situations reservoirs are
commingled to minimize investment risk and maximize economic
benefit. In particular, wells having different intervals and
marginal reserves may be commingled to reduce economic risk. One of
the risks in these applications is that sand failure and/or water
breakthrough in any one of the intervals threatens the remaining
reserves in the other intervals of the completion.
[0008] While typical sand control, remote control technologies and
interventions may be utilized, these approaches often drive the
cost for marginal reserves beyond the economic limit. As such, a
simple, lower cost alternative may be beneficial to lower the
economic threshold for marginal reserves and to improve the
economic return for certain larger reserve applications.
Accordingly, the need exists for a well completion apparatus that
provides a mechanism for managing the production of sand and water
within a wellbore, while being able to maintain dimensional
limitations.
[0009] Other related material may be found in at least U.S. Pat.
No. 5,722,490; U.S. Pat. No. 6,125,932; U.S. Pat. No. 4,064,938;
U.S. Pat. No. 5,355,949; U.S. Pat. No. 5,896,928; U.S. Pat. No.
6,622,794; U.S. Pat. No. 6,619,397; and International Patent
Application No. PCT/US2004/01599. Further, additional information
may also be found in Penberthy & Shaughnessy, SPE Monograph
Series--"Sand Control", ISBN 1-55563-041-3 (2002); Bennett et al.,
"Design Methodology for Selection of Horizontal Open-Hole Sand
Control Completions Supported by Field Case Histories," SPE 65140
(2000); Tiffin et al., "New Criteria for Gravel and Screen
Selection for Sand Control," SPE 39437 (1998); Wong G. K. et al.,
"Design, Execution, and Evaluation of Frac and Pack (F&P)
Treatments in Unconsolidated Sand Formations in the Gulf of
Mexico," SPE 26563 (1993); T. M. V. Kaiser et al., "Inflow Analysis
and Optimization of Slotted Liners," SPE 80145 (2002); and Yula
Tang et al., "Performance of Horizontal Wells Completed with
Slotted Liners and Perforations," SPE 65516 (2000).
SUMMARY
[0010] In one embodiment, a system associated with the production
of hydrocarbons is described. The system includes a first tubular
member and a second tubular member at least partially enclosing the
first tubular member disposed within a wellbore environment (e.g. a
subsurface environment). The first tubular member has a
non-permeable longitudinal section and a permeable longitudinal
section, wherein the permeable longitudinal section has a first
plurality of openings between a first central channel and a region
external to the first tubular member. The second tubular member
includes a non-permeable longitudinal section in substantial radial
alignment with the permeable longitudinal section of the first
tubular member and a permeable longitudinal section, wherein the
permeable longitudinal section of the second tubular member is in
substantial radial alignment with the non-permeable longitudinal
section of the first tubular member and the permeable longitudinal
section of the second tubular member is separated from the
permeable longitudinal section of the first tubular member by a
specific longitudinal distance. The specific longitudinal distance
is calculated based on geometry, fluid, and sand properties of the
wellbore environment. Also, the permeable longitudinal section of
the second tubular member has a second plurality of openings
between an internal region of the second tubular member and a
region external to the second tubular member that allows particles
having a particular size to pass therethrough. The system provides
a flow path for hydrocarbons through the first tubular member.
[0011] In an alternative embodiment, a system associated with the
production of hydrocarbons is described. The system includes a
wellbore utilized to produce hydrocarbons from a subsurface
reservoir, a production tubing string disposed within the wellbore,
a perforated base pipe coupled to the production tubing string and
disposed within the wellbore adjacent to the subsurface reservoir,
and a tubular member at least partially enclosing the perforated
base pipe. The perforated base pipe includes a non-permeable
longitudinal section and a permeable longitudinal section, wherein
the permeable longitudinal section has a plurality of slots between
a central channel of the perforated base pipe and a region external
to the perforated base pipe. The tubular member includes a
non-permeable longitudinal section disposed adjacent to the
permeable longitudinal section of the perforated base pipe and a
permeable longitudinal section of the tubular member having a
plurality of openings between an internal region of the tubular
member and a region external to the tubular member that permits the
passage of certain sized particles. Further, the permeable
longitudinal section of the tubular member is disposed adjacent to
the non-permeable longitudinal section of the perforated base pipe
and the permeable longitudinal section of the tubular member is
separated from the permeable longitudinal section of the perforated
base pipe by a specific longitudinal distance, which is calculated
based on geometry, fluid, and sand properties of the wellbore. The
system further includes producing hydrocarbons from the perforated
base pipe.
[0012] In another embodiment, a method associated with the
production of hydrocarbons is described. The method includes
measuring the geometry, fluid, and sand properties of a wellbore
environment and calculating a specific longitudinal distance
utilizing the measured properties. The method additionally includes
providing a first tubular member, wherein the first tubular member
comprises a non-permeable longitudinal section of the first tubular
member and a permeable longitudinal section of the first tubular
member that allows fluids to flow between a first central channel
and a region external to the first tubular member; providing a
second tubular member at least partially enclosing the first
tubular member, wherein the second tubular member comprises a
non-permeable longitudinal section of the second tubular member
disposed adjacent to the permeable longitudinal section of the
first tubular member and a permeable longitudinal section of the
second tubular member that allows fluids and sand particles to flow
between a second central channel and a region external to the
second tubular member, and the permeable longitudinal section of
the second tubular member; and disposing the non-permeable
longitudinal section of the first tubular member adjacent to the
permeable longitudinal section of the second tubular member,
wherein the permeable longitudinal section of the first tubular
member is separated from the permeable longitudinal section of the
second tubular member by a specific longitudinal distance. Further,
the method includes producing hydrocarbons from the first tubular
member.
[0013] In an alternative embodiment, a system associated with the
production of hydrocarbons is described. The system includes a
first tubular member and a second tubular member at least partially
enclosing the first tubular member. The first tubular member has a
non-permeable longitudinal section and a permeable longitudinal
section, wherein the permeable longitudinal section has a first
plurality of openings between a first central channel and a region
external to the first tubular member. The second tubular member
includes a non-permeable longitudinal section in substantial radial
alignment with the permeable longitudinal section of the first
tubular member and a permeable longitudinal section, wherein the
permeable longitudinal section of the second tubular member is in
substantial radial alignment with the non-permeable longitudinal
section of the first tubular member. Also, the permeable
longitudinal section of the second tubular member has a second
plurality of openings between an internal region of the second
tubular member and a region external to the second tubular member
that allows particles having a particular size to pass
therethrough. Further, a plurality of axial partitions is disposed
between the first and second tubular members to form a plurality of
chambers therebetween. The system provides a flow path for
hydrocarbons through the first tubular member.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] The foregoing and other advantages of the present technique
may become apparent upon reading the following detailed description
and upon reference to the drawings in which:
[0015] FIG. 1 is an exemplary production system in accordance with
certain aspects of the present techniques;
[0016] FIGS. 2A-2G are an exemplary embodiments of portions of a
sand control device utilized in the production system of FIG. 1 in
accordance with certain aspects of the present techniques;
[0017] FIGS. 3A-3D are exemplary embodiments of a compartment of
the sand control device within a wellbore of FIG. 1 in accordance
with certain aspects of the present techniques;
[0018] FIG. 4 is an exemplary embodiment of the sand control
devices within an open hole multi-zone well in accordance with
certain aspects of the present techniques;
[0019] FIG. 5 is an exemplary embodiment of the sand control
devices within a cased-hole multi-zone well in accordance with
certain aspects of the present techniques; and
[0020] FIG. 6 is an exemplary embodiment of the sand control
devices within an open-hole multi-zone well in accordance with
certain aspects of the present techniques.
DETAILED DESCRIPTION
[0021] In the following detailed description, the specific
embodiments of the present invention are described in connection
with its preferred embodiments. However, to the extent that the
following description is specific to a particular embodiment or a
particular use of the present techniques, it is intended to be
illustrative only and merely provides a concise description of the
exemplary embodiments. Accordingly, the invention is not limited to
the specific embodiments described below, but rather; the invention
includes all alternatives, modifications, and equivalents falling
within the true scope of the appended claims.
[0022] The present technique describes a sand control device and
method that may be utilized in a production system to enhance
production of hydrocarbons from a well and/or enhance the injection
of fluids or gases into the well. Under the present technique, a
sand control device is configured to utilize "tortuous paths" and
to promote the formation of sand bridges to plug relatively long
linear channels, passages or compartments within a sand control
device. Accordingly, when sand is produced, the sand bridges form
to plugs sections of a well to block the flow of sand and water
into the well from sand producing intervals or zones of the
formation. While plugging is generally considered a problem in
other sand control approaches, the present techniques promote
plugging in a controlled manner for water producing intervals of
the well. In fact, the plugging feature of present techniques may
be used to plug off sand producing intervals (with or without
water) protecting hydrocarbon production for other intervals within
the well. Thus, the present techniques utilize compartments in the
body of the device or relatively large compartments within the
production casing to create sand bridges when water is
produced.
[0023] Turning now to the drawings, and referring initially to FIG.
1, an exemplary production system 100 in accordance with certain
aspects of the present techniques is illustrated. In the exemplary
production system 100, a floating production facility 102 is
coupled to a subsea tree 104 located on the sea floor 106. Through
this subsea tree 104, the floating production facility 102 accesses
one or more subsurface formations, such as subsurface formation
107, which may include multiple production intervals or zones
108a-108n, wherein number "n" is any integer number, having
hydrocarbons, such as oil and gas. Beneficially, devices, such as
sand control devices 138a-138n, may be utilized to enhance the
production of hydrocarbons from the production intervals 108a-108n.
However, it should be noted that the production system 100 is
illustrated for exemplary purposes and the present techniques may
be useful in the production or injection of fluids from any subsea,
platform or land location.
[0024] The floating production facility 102 is configured to
monitor and produce hydrocarbons from the production intervals
108a-108n of the subsurface formation 107. The floating production
facility 102 may be a floating vessel capable of managing the
production of fluids, such as hydrocarbons, from subsea wells.
These fluids may be stored on the floating production facility 102
and/or provided to tankers (not shown). To access the production
intervals 108a-108n, the floating production facility 102 is
coupled to a subsea tree 104 and control valve 110 via a control
umbilical 112. The control umbilical 112 may be operatively
connected to production tubing for providing hydrocarbons from the
subsea tree 104 to the floating production facility 102, control
tubing for hydraulic or electrical devices, and a control cable for
communicating with other devices within the wellbore 114.
[0025] To access the production intervals 108a-108n, the wellbore
114 penetrates the sea floor 106 to a depth that interfaces with
the production interval 108a-108n at different intervals within the
wellbore 114. As may be appreciated, the production intervals
108a-108n, which may be referred to as production intervals 108,
may include various layers or intervals of rock that may or may not
include hydrocarbons and may be referred to as zones. The subsea
tree 104, which is positioned over the wellbore 114 at the sea
floor 106, provides an interface between devices within the
wellbore 114 and the floating production facility 102. Accordingly,
the subsea tree 104 may be coupled to a production tubing string
128 to provide fluid flow paths and a control cable (not shown) to
provide communication paths, which may interface with the control
umbilical 112 at the subsea tree 104.
[0026] Within the wellbore 114, the production system 100 may also
include different equipment to provide access to the production
intervals 108a-108n. For instance, a surface casing string 124 may
be installed from the sea floor 106 to a location at a specific
depth beneath the sea floor 106. Within the surface casing string
124, an intermediate or production casing string 126, which may
extend down to a depth near the production interval 108, may be
utilized to provide support for walls of the wellbore 114. The
surface and production casing strings 124 and 126 may be cemented
into a fixed position within the wellbore 114 to further stabilize
the wellbore 114. Within the surface and production casing strings
124 and 126, a production tubing string 128 may be utilized to
provide a flow path through the wellbore 114 for hydrocarbons and
other fluids. Along this flow path, a subsurface safety valve 132
may be utilized to block the flow of fluids from the production
tubing string 128 in the event of rupture or break above the
subsurface safety valve 132. Further, packers 134a-134n may be
utilized to isolate specific zones within the wellbore annulus from
each other. The packers 134a-134n may include external casing
packers, such as the SwellPacker.TM. (EZ Well Solutions) the
MPas.RTM. Packer (Baker Oil Tools), or any other suitable packer
for an open or cased hole well, as appropriate.
[0027] In addition to the above equipment, other devices or tools,
such as sand control devices 138a-138n, may be utilized to manage
the flow of particles into the production tubing string 128. The
sand control devices 138a-138n, which may herein be referred to as
sand control device(s) 138, may include slotted liners, stand-alone
screens (SAS); pre-packed screens; wire-wrapped screens, membrane
screens, expandable screens and/or wire-mesh screens. For exemplary
purposes, the sand control devices 138 are herein described as
being slotted basepipe with a perforated jacket, which is described
further below in FIGS. 2A-2G. The sand control devices 138 may
manage the flow of hydrocarbons from the production intervals 108
to the production tubing string 128.
[0028] As noted above, many wells have a number of completion
intervals with the formation strength varying from interval to
interval. Because the evaluation of formation strength is an
uncertain science, the ability to predict the timing of the onset
of sand and/or water is limited. Further, in many wells commingling
of production intervals 108a-108n may be preferred to minimize
investment risk and maximize economic benefit, which is
particularly true for intervals with marginal reserves. A major
risk in these applications is that sand failure and/or water
breakthrough in any one interval threatens the remaining reserves
in the well.
[0029] To address these concerns various sand and water control
methods are commonly used. For instance, typical sand control
methods include stand alone screens (also known as natural sand
packs), gravel packs, frac packs and expandable screens. These
methods limit sand production without increasing resistance to
produced fluids, such as hydrocarbons. By themselves these sand
control methods generally do not limit water production. Further,
typical excess water control methods include cement squeezes,
bridge plugs, straddle packer assemblies, and/or expandable
tubulars and patches. In addition, some other wells may include
chemical isolation methods, such as selective stimulation, relative
permeability modifiers, gel treatments, and/or resin treatments.
These methods are generally expensive, and utilize high risk
interventions after the onset of water production.
[0030] Despite the variety of other methods utilized, available
technology for controlling combined sand and water production is
generally complex and expensive. Indeed, the high cost of
conventional sand control, remote control technologies and
intervention costs that are utilized to manage sand and water
problems often drives cost for marginal projects beyond the
economic limit for a given well or field. As such, a simple lower
cost alternative is beneficial to lower the economic threshold for
marginal reserves and to enhance the economic return for certain
larger reserve applications. Accordingly, an exemplary sand control
device 138 is shown in greater detail in FIGS. 2A-2G below.
[0031] FIGS. 2A-2G are exemplary embodiments of portions of a sand
control device, such as one of the sand control devices 138a-138n,
utilized in the production system 100 of FIG. 1 in accordance with
certain aspects of the present techniques. Accordingly, FIGS. 2A-2G
may be best understood by concurrently viewing FIG. 1. In FIGS.
2A-2G, the different exemplary embodiments of the components, such
as a base pipe 202, axial rods 204a-204h, and an outer jacket 206,
of the sand control device 138 are shown. These components are
utilized to manage the flow of particles and water into the
production tubing string 128.
[0032] To begin, FIGS. 2A and 2B are an embodiment of the base pipe
202 and axial rods 204a-204h, which are coupled together. The base
pipe 202, which may be referred to as an inner flow tube or a first
tubular member, may be a section of pipe that has a central channel
208 and one or more openings, such as slots 210. The axial rods
204a-204h, which may be disposed longitudinal or substantially
longitudinal along the base pipe 202, are coupled to the base pipe
202 via welds or other similar techniques. For instance, the rods
204a-204h may attach to the base pipe 202 via welds and/or be
secured by end caps with welds. The base pipe 202 and the axial
rods 204a-204h may include carbon steel or corrosion resistant
alloy (CRA) depending on corrosion resistance intended for a
specific application, which may be similar to selection of material
for conventional screen applications. For an alternative
perspective of the partial view of the base pipe 202 and axial rods
204a-204h, a cross sectional view of the various components along
the line AA is shown in FIG. 2B.
[0033] To provide sand control, these slots 210 prevent or restrict
the flow of particles, such as sand, from passing between the
external region of the base pipe 202 and the central channel 208,
as discussed below in greater detail. The slots 210 may be
configured to prevent certain sized particles, such as sand, from
passing between the central channel 208 and a region external to
the base pipe 202. For instance, the slots 210 may be defined
according to "Inflow Analysis and Optimization of Slotted Liners"
and "Performance of Horizontal Wells Completed with Slotted Liners
and Perforations." See T. M. V. Kaiser et al., "Inflow Analysis and
Optimization of Slotted Liners," SPE 80145 (2002); and Yula Tang et
al., "Performance of Horizontal Wells Completed with Slotted Liners
and Perforations," SPE 65516 (2000). It should also be noted that
the sand control layer on base pipe 206 may be wire wrapped screen
and/or mesh type screens instead of slots in other embodiments.
[0034] Further, as part of this configuration, the slots 210 may be
positioned in groups along different longitudinal sections or
portions of the base pipe 202. That is, the sections of the base
pipe having the slots 210 may be referred to as permeable
longitudinal sections 212a-212c, while the closed or non-slotted
sections of the base pipe 202 may be referred to as non-permeable
longitudinal sections 214a-214b. The distribution of these sections
212a-212c and 214a-214b may be varied to provide different flow
paths into the central opening or channel 208, which is discussed
further below.
[0035] FIGS. 2C and 2D illustrate an outer jacket 206 disposed
around the base pipe 202 and axial rods 204a-204h. The outer jacket
206, which may be referred to as an outer flow tube, second tubular
member and/or jacket, may be a section of pipe with openings or
perforations 218 along the length of the outer jacket 206. The
perforations 218 may be sized to minimize flow restrictions (i.e.
sized to allow particles, such as sand to pass through the
perforations 218). The perforations may be shaped in the form of
round holes, ovals, and/or slots, for example. The outer jacket 206
may include carbon steel or CRA, as discussed above. For an
alternative perspective of the partial view of the outer jacket
206, a cross sectional view of the various components along the
line BB is shown in FIG. 2D.
[0036] Similar to the base pipe 202, the perforations 218 may be
positioned in groups along different portions of the outer jacket
206. That is, sections of the outer jacket 206 having the
perforations 218 may be referred to as permeable longitudinal
sections 220a-220b, while the non-perforated sections of the outer
jacket 206 may be referred to as non-permeable longitudinal
sections 222a-222c. The distribution of these sections 220a-220b
and 222a-222c may be varied to provide different flow paths into
the central opening 216, which is discussed further below.
[0037] FIGS. 2E and 2F illustrate an embodiment with the outer
jacket 206 disposed around the base pipe 202 and axial rods
204a-204h. The outer jacket 206 is secured to the base pipe 202 via
the axial rods 204a-204h. This coupling may be made by welds or
other similar techniques, as noted above. For instance, the outer
jacket 206 may slide onto the base pipe 202 and axial rods
204a-204h, which are welded together. Then, ends of the outer
jacket 206 may be secured to the base pipe 202 and axial rods
204a-204h by welds with end caps. Alternatively, the axial rods
204a-204h may be secured to the outer jacket 206 with welds and
then slid onto the base pipe 202, which is again secured with end
caps. For an alternative perspective of the partial view of the
base pipe 202, axial rods 204a-204h and outer jacket 206, a cross
sectional view of the various components along the line CC is shown
in FIG. 2F.
[0038] As discussed above, the sections 220a-220b and 222a-222c of
the outer jacket 206 may be longitudinally aligned with specific
sections 212a-212c and 214a-214b of the base pipe 202. For
instance, permeable longitudinal sections 220a-220b of the outer
jacket 206 may be aligned with the non-permeable longitudinal
sections 214a-214b of the base pipe 202. Similarly, the
non-permeable longitudinal sections 222a-222c of the outer jacket
206 may be aligned with the permeable longitudinal sections
212a-212c of the base pipe 202. In this configuration, the
perforations 218 in the outer jacket 206 and slots 210 in the base
pipe 202 may be offset by a specific distance, which may be
referred to as a specific longitudinal distance, to divert the
radial flow path through the openings 216 to a linear flow path
along the axis of the base pipe 202 between the axial rods
204a-204h to the slots 210. At the slots 210, the flow is again
diverted to a radial flow path through the slots 210 into the
central channel 208. The distance of the linear flow path between
the perforations 218 and the slots 210 (i.e. the "specific
longitudinal distance") is designed to provide the desired degree
of plugging and isolation for the sand control device 138, which is
discussed further below.
[0039] FIG. 2G illustrates an embodiment of the assembled sand
control device 138a with the end caps 230-232 disposed around the
base pipe 202, axial rods 204a-204h and outer jacket 206. Each of
the end caps 230-232, which include neck sections 238a-238b, may
include one set of threads 234-236 that are utilized to couple the
sand control device 138a with other sand control devices, sections
of pipe and/or other devices. The end caps 230-232 may be coupled
to the outer jacket 206, axial rods 204a-204h and/or the base pipe
202 at neck regions 238a-238b, which include sections 240a-240b,
respectively. In the neck regions 238a-238b, the end caps 230-232,
outer jacket 206, axial rods 204a-204h and base pipe 202 may be
welded in a manner similar to that performed on wire wrapped
screens. The base pipe 202 may extend beyond either end of the
outer jacket 206 to provide room for tubing connections, for
connecting sections of sand control devices together, or for
connecting other tools with the sand control device 138a.
[0040] Beneficially, by providing slots 210 and perforations 218 in
specific sections of the base pipe 202 and outer jacket 206, the
flow paths may be relatively long to ensure the channels formed
between the base pipe 202, axial rods 204a-204h and outer jacket
206 plug when sand is produced from the production interval. Unlike
other approaches that use tortuous flow path concepts to increase
erosion resistance of primary sand control devices and to manage
pressure drop across completions for balancing flow profiles, the
present embodiment uses longer linear flow paths to plug the
compartment, not short flow paths, which may not plug the sand
control device to prevent or restrict the flow of fluids.
Accordingly, the tortuous flow path created by the distance
separating the slots 210 and perforations 218 are utilized to plug
off flow and associated water production to protect the remaining
intervals in the well. That is, the perforations 218 of the outer
jacket 206 are simply utilized to divert flow, while the slots 210
are the sand control device that blocks sand. As such, the present
embodiment utilized the tortuous flow path to provide a mechanism
that creates sand bridges to plug the flow path into the slots
210.
[0041] In addition, the present embodiment provides an automated
mechanism for managing a sand control device without user
intervention, high cost, risky intervention or without relying on
expensive sensors to determine the conditions within the wellbore.
As noted above, other approaches utilize mechanical and chemical
techniques that rely upon user intervention to re-enter the
wellbore, to actuate pre-installed downhole devices, to install
shut off devices (plugs, patches etc) and/or to pump some chemical
to block off the unwanted water producing interval. These active
devices are complex and expensive to implement. However, the
present embodiment is a passive shut-off device. In fact, the base
pipe 202, axial rods 204a-204h and outer jacket 206 in this
embodiment do not even have moving parts. As such, the plugging of
the interval of the wellbore adjacent to the sand control device is
automatically performed without user intervention.
[0042] As an example, FIGS. 3A-3D are exemplary embodiments of the
present techniques in a single chamber or compartment 300 of the
sand control device, which may be sand control device 138a, within
the wellbore 114 of FIG. 1 in accordance with certain aspects of
the present techniques. Accordingly, FIGS. 3A-3B may be best
understood by concurrently viewing FIGS. 1, 2A-2G. In FIG. 3A,
fluid flow is shown along the production flow path 302. As
discussed above, a compartment is formed between the base pipe 202
and the outer jacket 206. By offsetting the perforations 218 from
the slots 210 by a specific distance 305, which is the specific
longitudinal distance, the production flow path 302 follows a
radial path to pass through the perforations 218. Then, the
production flow path 302 passes through the compartment along a
relatively long, narrow path through the slots 210 of the base pipe
202 into the central channel 208 within the base pipe inner
diameter (ID). From the slots 210, fluids pass into the central
channel 208 and through the production tubing string 128 to the
floating production facility 102.
[0043] However, when sand is produced, a sand bridge 306 forms to
block the fluid flow path 302 into the compartment 300, as shown in
FIG. 3B. In FIG. 3B, the sand bridge 306 prevents fluids, such as
water and hydrocarbons, and particles, such as sand, from passing
into the central channel 208 formed by the base pipe ID. As a
result, the flow path 302 is plugged within the compartment. This
blocking flow path 302 continues to fill the compartment with
particles until the compartment forms a complete or partial barrier
to fluids and particles. In certain applications where water
production destabilizes the formation and causes sand production,
the sand bridge 306 created by the sand control device 138a may
limit or prevent further sand and water production within the
interval of the wellbore that the sand control device 138a is
installed. Beneficially, this limits the impact of sand and water
on the integrity of production from other intervals, wells and the
facilities.
[0044] The distance 305 is calculated based on the geometry, fluid
properties and sand properties of the well using common models for
fluid flow in porous media. In particular, the distance 305 is
calculated to achieve a target pressure drop at a given flow rate
and provide sufficient resistance to fluid flow once the
compartment is at least partially filled with sand. The calculation
may be based on commonly used models/equations for fluid flow in
porous media. Some of the specific parameters that may be utilized
in determining the distance 305 may include the cross sectional
flow area of the chamber, the permeability of the plugging material
(i.e. the sand filling the chamber) and fluid properties (i.e.
viscosity). These properties may be known values or may be
theoretical properties derived from experience, experimentation,
data from related well sites, and other sources.
[0045] A further advantageous aspect of the present techniques is
shown in FIGS. 3C-3D. FIG. 3C shows an axial view of one embodiment
of a sand control device 138a in accordance with the present
techniques disposed within a production interval 108a-108n of a
wellbore 114. The flow from the production interval 310 may enter
any one of a plurality of axial chambers 312a-312h formed by the
basepipe 202, the outer jacket 206, and the plurality of axial rods
204a-204h. However, when sand is produced, a sand bridge 306 forms
in at least one of the plurality of axial chambers 312a-312h to
prevent fluids, such as water and hydrocarbons, and particles, such
as sand, from passing into the central channel 208 formed by the
base pipe ID. As a result, the flow path 310 is plugged within the
at least one axial chamber while the remaining axial chambers
remain open to fluid flow unless or until those axial chambers are
filled with sand. Beneficially, this allows for finer control over
the production of sand and water by blocking only those
longitudinal and radial portions of the production interval in
which sand and water are being produced, while allowing the flow of
hydrocarbons in specific areas where sand and water production are
not present. A skilled artisan will recognize that a different
chamber configuration and a different number of chambers is within
the scope of this embodiment.
[0046] Furthermore, sand control device may provide enhancements to
a multi-zone reservoir or formation, such as subsurface formation
107. For example, a subsurface formation 107 may include multiple
production zones or intervals 108a-108n that produce sand free for
some period of time. These intervals may be isolated or commingled
with other production intervals within the well. Typically, after a
certain amount of depletion/drawdown or with the onset of water
production from different production intervals, premature water
breakthrough and/or sand failure may threaten the other production
intervals of the well. However, with the present sand control
devices, sand failure in a specific interval may plug off as the
linear flow channels through and adjacent to the sand control
device fill with sand and plug. As a result, any producing
production intervals may continue to provide hydrocarbons, while
the sand control devices 138a-138n may block the flow of sand and
water from depleted production intervals 108a-108n. Accordingly,
the use of the exemplary sand control devices with multiple
production intervals within a well is shown in greater FIGS. 4-6
below.
[0047] FIG. 4 is an exemplary embodiment of the sand control
devices 138a-138n within the wellbore 114 of FIG. 1 in accordance
with certain aspects of the present techniques. Accordingly, FIG. 4
may be best understood by concurrently viewing FIGS. 1, 2A-2G and
3A-3B. In FIG. 4, which may be a preferred use of the sand control
devices 138a and 138b, a section of the wellbore 114 is shown with
sand control devices 138a and 138b disposed adjacent to production
intervals 108a and 108b. In this section, packers 134a, 134b and
134c are utilized with the sand control devices 138a and 138b to
provide separate compartments that each access one of the
production intervals 108a and 108b. With the sand control devices
138a and 138b located across the respective production intervals
108a and 108b, fluid flow paths, such as fluid flow path 402, for
example, may be formed to allow fluids to flow from the production
intervals 108a and 108b into the production tubing string 128 for
each of the compartments. The distance (length of compartment,
distance from holes in outer jacket to slots in base pipe) is
calculated based on the geometry, fluid properties and sand
properties, as discussed above. If one zone, such as production
interval 108a, begins to produce sand, the produced sand fills the
compartments in the sand control devices 138a. Flow resistance
through the sand control device 138a increases as the compartments
fill with sand effectively restricting flow from the sand producing
interval. In particular, the production of sand is shown in sand
control device 138a, which forms a sand bridge 403 that blocks
fluid flow from this interval 108a. However, the flow path 402
through the sand control device 138b may continue to produce
fluids.
[0048] FIG. 5 is an exemplary embodiment of the sand control
devices 138a-138n disposed within a wellbore 500 for a cased-hole
well in accordance with certain aspects of the present techniques.
Accordingly, FIG. 5, which may utilize components discussed in
FIGS. 1, 2A-2G and 3A-3B, may be best understood by concurrently
viewing FIGS. 1, 2A-2G and 3A-3B. In the wellbore 500, perforations
518a-518b are created through the production casing string 126 and
cement 516 to provide flow paths from production intervals
504a-504b of a subterranean formation, which may be similar to
subterranean formation 107 of FIG. 1, to the production tubing
string 128 via the sand control devices 502a-502d. These sand
control devices 502a-502b may include various components that are
configured to be located specific distances from or relative to the
perforations 518a-518b. With the specific configuration, the flow
paths created may limit or prevent sand and water production within
the production intervals 504a-504b of the wellbore 500, as
discussed above.
[0049] In FIG. 5, which may be a preferred use of the sand control
devices 502a-502b, a section of the wellbore 500 is shown with sand
control devices 502a-502b disposed adjacent to production intervals
504a-504b. In this section, packers 506a, 506b and 506c, which may
be similar to packers 134a-134n, are utilized with the sand control
devices 502a-502b to provide separate compartments that each access
one of the production intervals 504a-504b. The sand control devices
502a-502b may include erosion resistant blast joints 508a-508b and
sand screens 510a-510b disposed around basepipes 512a-512b that
have openings (not shown) underneath the sand screens 510a-510b.
The openings within the base pipes 512a-512b may be configured to
allow fluids to flow into the basepipes 512a-512b, while particles
of a specific size are blocked by the sand screens 510a-510b, as
discussed above. The erosion resistant blast joints 508a-508b may
be utilized to form perforations 518a-518b at a specific location
relative to the sand screens 510a-510b.
[0050] Similar to the discussion above, the openings in the sand
control devices 502a-502b may be located a sufficient distance
505a-505b across the respective production interval 504a-504b.
However, in this configuration, the annulus between the production
casing string 126 and the basepipes 512a-512b is utilized as the
longer linear flow paths to plug the compartment of the annulus to
prevent flow. For instance, fluid flow paths, such as fluid flow
path 514, may be formed to allow fluids to flow from the production
intervals 504a-504b into the production tubing string 128. As the
fluid flows from the production intervals 504a-504b through the
cement 516 and respective perforations 518a-518b into the
production tubing string 128 for each of the compartments, a
longitudinal distance 505a-505b separates the perforations
518a-518b from the sand screens 510a-510b to cause the fluid
pressure to drop along the flow path 514. Accordingly, a sand
bridge may form adjacent to the one of the sand control devices
502a-502b because of the pressure drop of fluid flowing through the
perforations 518a-518b and the annulus between the sand control
device 502a-502b and the production casing string 126. This sand
bridge may effectively restrict the flow of fluids from the sand
producing production interval. In particular, the formation of a
sand bridge 517 adjacent to the sand control device 502a blocks
fluid flow from the production interval 504a into the production
tubing string 128. However, the flow of fluids from the production
interval 504b may continue to produce fluids through the sand
control device 502b.
[0051] FIG. 6 is an exemplary embodiment of the sand control
devices 138a-138n disposed within a wellbore 500 for an open-hole
multi zone well in accordance with certain aspects of the present
techniques. Accordingly, FIG. 6, which may utilize components
discussed in FIGS. 1, 2A-2G and 3A-3B, may be best understood by
concurrently viewing FIGS. 1, 2A-2G, 3A-3B and 5. In FIG. 6, flow
paths from production intervals 604a-604b of a subterranean
formation, which may be similar to subterranean formation 107 of
FIG. 1, to the production tubing string 128 may be formed by
disposing the sand control devices 502a-502b within the wellbore
600. These sand control devices 502a-502b, which are discussed
above, may include various components that are configured to be
located specific distances from or relative to the production
intervals 604a-604b. With the specific configuration, the flow
paths created may limit or prevent sand and water production within
the production intervals 604a-604b of the wellbore 600, as
discussed above.
[0052] Similar to the discussion above, the openings in the sand
control devices 502a and 502b may be located a sufficient distance
605a-605b above the respective production interval 604a-604b.
Open-hole packers 602a-602b may be disposed between production
intervals 604a-604b to isolate different zones. However, in this
configuration, the annulus formed between the walls of the wellbore
600 and the basepipes 512a-512b is utilized as the linear flow
paths to plug the compartment of the annulus to prevent flow. For
instance, fluid flow paths, such as fluid flow path 608, may be
formed to allow fluids to flow from the production intervals
604a-604b into the production tubing string 128. As the fluid flows
from the production intervals 604a-604b through the annulus into
the production tubing string 128 for each of the compartments, a
longitudinal distance 605a-605b separates the production intervals
604a-604b from the sand screens 510a-510b to cause the fluid
pressure to drop along the flow path 608. Accordingly, a sand
bridge may form adjacent to the one of the sand control devices
502a and/or 502b because of the pressure drop of fluid flowing from
the production intervals 604a and 604b in the annulus between the
sand control device 502a-502b and walls of the wellbore 600. This
sand bridge may effectively restrict the flow of fluids from the
sand producing production interval. In particular, the formation of
a sand bridge 610 adjacent to the sand control device 502a blocks
fluid flow from the production interval 604a into the production
tubing string 128. However, the flow of fluids from the production
interval 604b may continue to produce fluids through the sand
control device 502b.
[0053] Beneficially, the various combinations of these sand control
devices 138a-138n and 502a-502b in FIGS. 4-6 may be utilized to
control the production of sand and water for various production
intervals or zones of a well. In fact, this control of sand and
water production may be performed in a self-mitigating manner
without user intervention (i.e. automatically). While one of the
production intervals may be blocked by a sand bridge, other
production intervals may continue to produce fluids unimpeded by
sand and/or water production from the blocked production interval.
Further, because this mechanism does not have any moving parts or
components, it provides a low cost mechanism to exclude sand and
shut off water production for certain oil field applications.
Accordingly, the different configurations provide sand and water
control with a long tortuous path formed by the outer jacket and
base pipe.
[0054] The present techniques also encompass the placement of a
tubular member over a previously disposed basepipe. For example,
some wells may already have a perforated basepipe disposed in them
to allow production fluid coming into the well, but lack a
concentric pipe or tubular member to plug off unwanted fluid coming
into the wellbore. These wells may not have produced sand and water
at the time the basepipe was originally placed, but have begun to
produce sand and water or are likely to begin producing such
byproducts. In a case such as this, an operator may position a
perforated tubular member inside the original basepipe at certain
intervals determined to inhibit the production of sand and water
through the basepipe. The size and placement of the openings along
the pipe's length could be calculated based on measured properties
of the wellbore environment.
[0055] It should be noted that any number of compartments may be
formed within production intervals. For instance, as shown in FIGS.
4-6, one or more sand control devices may be utilized together to
form a single compartment that includes multiple production
intervals. In addition, one or more of the sand control devices may
also be utilized with a single production interval. In this
configuration, the different sand control devices may provide
different zones or sections of control for a single production
interval.
[0056] Further, as another variation on the embodiments described
above, it should be appreciated that the sand screens 510a-510b in
FIGS. 5 and 6 may be positioned or disposed below the respective
producing interval 504a-504b and 604a-604b. This adjustment to the
location of the sand screens 510a-510b in FIGS. 5 and 6 may provide
benefits for certain applications and function in the same manner
as described above. Also, sand screens 510a-510b may also be
positioned above and below the producing intervals 504a-504b and
604a-604b. This configuration may be beneficial in high rate
production applications. As such, different configurations may be
utilized with the described embodiments to provide this
functionality a production system.
[0057] While the present techniques of the invention may be
susceptible to various modifications and alternative forms, the
exemplary embodiments discussed above have been shown by way of
example. However, it should again be understood that the invention
is not intended to be limited to the particular embodiments
disclosed herein. Indeed, the present techniques of the invention
are to cover all modifications, equivalents, and alternatives
falling within the spirit and scope of the invention as defined by
the following appended claims.
* * * * *